Drilling of most oil and gas wells includes the use of a drilling fluid, commonly known as drilling mud. The fluid is injected under pressure through the drill string during drilling and returns to the surface through the drill string-borehole annulus. Once returned to the surface, the drilling fluid contains cuttings from the drill bit. Although most large cuttings are removed at the surface prior to recirculating the fluid, smaller sized particles remain suspended within the drilling fluid.
In addition to the removal of drilled cuttings from the wellbore, drilling fluids perform other functions. Such functions include cooling of the drill bit, lubrication of the drill bit, optimizing the transmission of hydraulic energy to the drill bit, increasing the stability of the borehole and providing hydrostatic pressure to prevent the collapse or high pressure geologic zones when such zones are penetrated by the drill bit.
Four properties must be balanced when selecting a proper drilling fluid: viscosity, density, gel strength, and filtration.
Generally, viscosity is maintained as low as possible to provide the required hole stability and fluid loss control. While thin fluids generally clean the drill bit best, thick muds are often essential in order to remove coarse gravel from the hole.
An increase in density, defined as the weight per unit volume of drilling fluid, is a measure of the quantity of drilled material being carried in suspension and re-circulated. Excess suspended cuttings are not desired since they are generally abrasive and increase wear on the pump, drill string and drill bit. Re-grinding of cuttings also tends to decrease the rate of the drilling progress. Further, a higher concentration of solids in the fluid generally results in the formation of a thicker filter cake on the walls of the borehole.
Gel strength is the measure of the capability of a drilling fluid to hold particles in suspension after flow ceases. Keeping cuttings in suspension prevents sandlocking of tools in the borehole while joints of drill pipes are added to the drill string and minimizes sediment collecting in the bottom of the hole. A drawback to high gel strength is the failure of cuttings to readily settle out of the drilling mud. This normally means that such cuttings will be re-circulated, thus resulting in grinding of particles by the drill bit, increased mud density, increased mud pump wear, and lower penetration rate.
Filtration refers to the ability of the drilling fluid to limit fluid loss to the formation by deposition of mud solids in the form of a filter cake on the walls of the hole. While the ideal filter cake is thin with minimum fluid loss by intrusion into the formation, the thickness of the filter cake for a mud is generally a function of the permeability of the formation. A thick filter cake has a number of disadvantages which include the erosion of the filter cake by circulating drilling fluid, sticking of the drill pipe, reduction of hydrostatic pressure and partial collapsing of the walls of the borehole during tool removal.
Drilling fluids used in oil and gas exploration today are principally water based or oil based (including synthetic oil based). Often, oil based fluids are not desired since there present greater handling concerns and fire hazards. In addition, oil based fluids are environmentally unacceptable compared to water based muds. Further, the cost per barrel of oil based muds is higher versus water based muds since oil is much more expensive than water. The justification for selecting an oil based mud over an aqueous based mud is normally attributable to its superior performance under particular conditions of use. For instance, oil based fluids generally offer superior lubricity properties over water based fluids. Further, with certain hydrophilic formations, such as shale, oil based fluids are normally preferred since penetration of the formation by water is avoided. Shales can be drilled in the presence of hydrous clays and bentonites, with no swelling or sloughing, which might cause pipe sticking difficulties. Furthermore, oil based muds may be formulated to withstand temperatures up to 500° F.
More recently, synthetic oil based muds have become prominent which contain synthetic polymers. While synthetic oil based muds often have enhanced performance capabilities, they are significantly more expensive. In light of increased environmental risks, additional costs relating to wellsite housekeeping, transportation and approved disposal of oil-based fluids, synthetic oil based fluids and drilled cuttings, there has been renewed interests in the development of improved water-based drilling fluids.
Typically, water based drilling fluids consist of a liquid phase and a suspended solid phase. The liquid phase is either fresh or saline water. The solid phase, which is suspended within the liquid phase, can comprise a multitude of materials blended to meet the particular needs at hand. As an example, barite (barium sulfate), with a specific gravity over 4.1, is often used as a weighting constituent to increase the bulk density of the drilling fluid when high pressure formations are being penetrated. Other additives are used to control drilling fluid circulation loss when certain types of high porosity, low pressure formations are penetrated.
Typically, the requisite viscosity of the drilling fluid is provided by one or more viscosifying agents. The viscosifying agent further serves to promote the suspension of the weighting agent in the fluid. A commonly used viscosifying agent is sodium montmorillonite (bentonite), a naturally occurring commercial clay. Bentonite, however, has inherent performance limitations in certain oil well drilling applications—particularly when high geological formation temperature combines with other geological contaminants such as carbon dioxide and hydratable drilled solids cause undesirable elevated viscosity. This condition is often hard to control and expensive to rectify.
Other viscosifying agents have been reported in the literature. For example, xanthan gum is often used, with or without bentonite, to slow or prevent sedimentation of weighting agents.
Further, there is a great need for aqueous based drilling fluids which exhibit the same or nearly the same lubricity as oil based fluids. Lubricity is normally measured by the coefficient of friction of the fluid; fluids exhibiting lower coefficients of friction providing greater lubricity. The coefficient of friction for oil based fluids is normally between from about 0.07 to 0.13; the coefficient of friction for water based fluids being normally between from about 0.17 to about 0.30.
In addition, there is a need for water based drilling fluids which, like oil based drilling fluids, are capable of withstanding high temperatures, i.e., in excess of 500° F.
Further, there is a need for water based drilling fluids which are bentonite free, exhibit negligible viscosity at elevated temperatures and which minimize the effect of carbon dioxide and other contaminants on the fluid system.